Method and system for determining downhole optical fiber orientation and/or location

ABSTRACT

A probe is provided that contacts the inner surface of the casing or other production tubing and imparts energy to the surface at the contact point, for example as heat energy or mechanical energy. Energy is imparted around the circumference of the casing, and a fiber optic distributed sensor located on the outer surface of the casing is used to measure and record the energy that it receives whilst the probe is moved to impart energy around the circumference. A record of energy versus position of the probe around the circumference can be obtained, from which maxima in the detected energy measurements can then be found. The position around the circumference which gave the maximum measurement should be the position at which the optical fiber of the fiber optic distributed sensor is located. In addition, an ultrasonic arrangement is also described, that relies on ultrasonic sound to provide detection.

TECHNICAL FIELD

The present invention provides a method and system for determining theorientation or location of optical fiber deployed downhole, andparticularly optical fiber used for distributed acoustic or temperaturesensing. Particular embodiments provide a method and system that ensurethat the perforation gun will not damage any optical fibres installed inthe well.

BACKGROUND TO THE INVENTION AND PRIOR ART

To detect an acoustic signal downhole, distributed acoustic sensing(DAS) is commonly and effectively used. This method employs fibre opticcables to provide distributed acoustic sensing whereby the fibre opticcable acts as a string of discrete acoustic sensors, and anoptoelectronic device measures and processes the returning signal. Theoperation of such a device is described next.

A pulse of light is sent into the optical fibre, and a small amount oflight is naturally back scattered, along the length of the fibre byRayleigh, Brillouin and Raman scattering mechanisms. The scattered lightis captured by the fibre and carried back towards the source where thereturning signal is measured against time, allowing measurements in theamplitude, frequency and phase of the scattered light to be determined.If an acoustic wave is incident upon the cable, the glass structure ofthe optical fibre is caused to contract and expand within thevibro-acoustic field, consequently varying the optical path lengthsbetween the back scattered light scattered from different locationsalong the fibre The returning signal can be processed in order tomeasure the acoustical and/or vibrational field(s) at all points alongthe structure.

In known distributed acoustic sensing systems (DAS), standard fibreoptic cables are utilised to obtain a measurement profile from along theentire length of the fibre at intervals ranging from 1-10 metres.Further details regarding the operation of a suitable DAS system, suchas the iDAS™, available from Silixa Limited, of Elstree, UK are given inWO2010/0136809. Systems such as these are able to digitally recordacoustic fields at every interval location along an optical fibre atfrequencies up to 100 kHz. Since the location of the acoustic sensors isknown (the fibre deployment being known), the position of any acousticsignal can be thus identified by means of time-of-arrival calculations.

DAS systems find lots of applications in the oil and gas industry, andoptical fibers that can be connected to DAS systems, amongst otherthings, are often installed within wellbores, usually as a metal cablerunning parallel with the well bore casing clamped to the outsidethereof. In a typical oil or gas well, once the well bore has beendrilled and the casing installed, cement is used to fill the well boreexternal of the casing. However, as part of the “completion” process ofthe well, the casing and cement is perforated within the hydrocarbonbearing regions, to allow hydrocarbons to flow into the casing forextraction. Perforation is typically performed by a perforating gun,which is typically a cylindrical metal tube provided with shapedexplosive charges arranged around the circumference thereof. Theperforating gun is lowered through the casing to the intended productionzone, and the shaped charges are detonated, with the intention ofblasting holes through the casing and cement of the well, and into thesurrounding rock strata, to allow hydrocarbons to then flow through thecreated channels into the casing for extraction. Similarly, where afracturing fluid is to be pumped into the well to fracture the rockstrata, the created holes provide routes for the fracturing fluid toexit the well into the surrounding rock.

FIG. 1 illustrates the use of a perforating gun to generate perforationsin a well bore casing and cement, and into the surrounding rock strata.Perforating gun 10 comprises a metal cylinder provided with shapedexplosive charges arranged around the outer surface thereof. Forexample, the shaped charges may be provided in lines every 120 degreesaround the outer circumference of the gun. The gun is provided with acommunications line 12 to the surface for control purposes, to allow theexplosive charges to be detonated on command. In use as noted above thegun is lowered to the intended production zone, and the shaped chargesdetonated to blast through the casing and cement (as shown in FIG.1(b)), to create production channels in the surrounding rock stratathrough which oil or gas can flow to enter the well bore (as shown inFIG. 1 (c)).

One issue with the use of perforating guns is to try and prevent theshaped charges from damaging any control or sensing cabling or otherlines that may extend along the wellbore external of the casing. Forexample, optical fibers are commonly installed along the externalsurface of the casing within the wellbore, either for sensing purposesand/or for control of downhole tools. Care must be taken when using aperforating gun that the shaped charges are not pointed at the externalcabling or other lines such that the charges when detonated would seversuch lines. As the perforating is performed as part of the wellcompletion, by that point the fibers have typically already beencemented into the well bore, and hence repair can be very costly, oreven impossible. To try and prevent such damage occurring,conventionally the fibers and other signalling lines are located betweentwo metal rods or cables, and a magnetometer is provided on theperforating gun to try and detect the metal rods. That is, therotational orientation of the perforating gun is altered within thecasing whilst the magnetometer is used to detect the location of themetal rods either side of the fibers or other cabling. Once the metalrods have been detected, the orientation of the perforating gun can becontrolled to ensure that the shaped charges are pointed away from thearea of the metal rods, and hence the cabling or other lines to beprotected.

One problem with the above arrangement is one of cost, in that the metalrods are usually required to extend along a significant length of thewell bore, hence increasing the material and production cost of thewell. In addition, the use of magnetometers to detect the rods is notparticularly accurate, and particularly in some rock formations or insome regions where magnetic anomalies can occur that interfere with theoperation of the magnetometers. Moreover, the presence of the casing andother downhole equipment can interfere with the proper operation of themagnetometers, meaning that it is not reliably possible to rotationallyorient the perforating gun within the casing to ensure that the sensorand control lines and/or other cabling will not be damaged by the use ofthe perforating gun. In addition, the rods also from a potential leakagepath up the outside of the casing.

In order to address this problem WO2013/030555 describes a method andapparatus for determining the relative orientation of objects downhole,and especially to determining perforator orientation. The method,illustrated in FIG. 2, involves varying the orientation of an object,such as a perforator gun (302) in the wellbore and activating at leastone directional acoustic source (402 a-c). Each directional acousticsource is fixed in a predetermined location to the object and transmitsan acoustic signal preferentially in a known direction. The directionalacoustic source(s) is/are activated so as to generate sound in aplurality of different orientations of said object. An optical fiber(104) deployed down the wellbore is interrogated to provide distributedacoustic sensing in the vicinity of the object and the acoustic signalsdetected by the optical fiber are analyzed so as to determine theorientation of the at least one directional acoustic source relative tothe optical fiber, for instance by looking at the relative intensity inthe different orientations. Further details of the operation of thearrangement are described in the document, any and all of whichnecessary for understanding the present invention being incorporatedherein by reference.

Therefore, whilst the arrangement in WO2013/030555 apparently shouldovercome the cost and inaccuracy of the prior art magnetometerarrangements, the arrangement relies on the operation of a DAS system todetect the directional acoustic sources, with the directional acousticsources being described as conventional loudspeakers arranged to projectsounds forward and located in a casing that absorbs sound emitted inother directions. Conventional loudspeakers typically operate withinaudible frequency bands, for example in the range 20 Hz to 20 kHz, and atypical DAS of the prior art is usually capable of detecting sound atthese frequencies with good spatial resolution. However, thedirectionality of conventional loudspeakers, even provided in anotherwise insulating casing, is not high, and −3 dB directivity arcs of+/−50 to 60° can be common FIG. 2 has been annotated to show typicalexample—directivity arcs for the three loudspeakers. As shown, suchdirectivity often means that even if the speaker is pointed away fromthe optical fibre, the fiber may still pick up a large signal from thespeaker. Allowing further for echoes and other multi-path effects withinthe casing, and the reliability of such a system begins to deteriorate.Basically, using conventional speakers as described in the prior artdoes not give a high enough directivity for the sound emitted toreliably determine the orientation of the perforating gun.

SUMMARY OF THE INVENTION

In order to address the above problem, alternative mechanisms to locatethe optical fiber are necessary, that are more accurate than theconventional audio speaker based method of the prior art. Suchmechanisms include a downhole device adapted to be inserted into awellbore, the downhole device being arranged to contact an interiorsurface of the well-bore to impart energy to the surface at the contactpoint, or to detect energy imparted to the surface at the contact point.The downhole device may include a transducer arranged to contact aninterior surface of the wellbore to impart energy to the surface at thecontact point, wherein the imparted energy may be detected by an opticalfiber sensing system comprising the optical fiber to be located.Alternatively, the downhole device may include at least one sensorarranged to contact an interior surface of the wellbore to detect energyimparted to the surface at the contact point, wherein energy has beenimparted to an exterior surface of the wellbore by the optical fiber tobe located. Both of these solutions to the above noted problem andvariations thereof will now be described in more detail.

A first mechanism uses a mechanical tapper arrangement to tap againstthe inner surface of the casing or tubing, with the position of thetapper rotationally changing so as to tap substantially around the innercircumference of the inner surface. The fiber optic based distributedsensor is operated as a distributed acoustic sensor and records theamplitude of the taps as the tapper rotates so as to tap around theinner circumference of the casing or other tubing. A maxima is thenfound in the amplitude record of the taps, that should be at theposition where the tapper is tapping at a position closest to theoptical fiber i.e. the maxima in the amplitude record should indicatethe general position of the fiber circumferentially at that position inthe casing.

A second mechanism is related, but instead of using a mechanical tappera heated probe is used that is circumferentially rotated around theinner surface of the casing or other tubing, so as to locally heat thecasing the vicinity of the contact point. In this case, the fiber opticdistributed acoustic sensor is operated as a distributed temperaturesensor, and the local heating of the casing by the heated probed when itis pointing in the direction of the circumferential location of theoptical fiber outside the casing or other tubing is detected by theoptical fiber as an increase in local temperature. Again, by knowing therotational position of the heated probe around the inner circumferenceof the casing or other tubing at the temperature maxima then theposition of the optical fiber can be inferred as being at that position.

In one variation of the second mechanism, the transducer may be a probecomprising a heated end adapted to heat the interior surface of thewellbore and a cooled end adapted to cool the interior surface of thewellbore. Here the local heating of the casing by the heated end when itis pointing in the direction of the circumferential location of theoptical fiber outside the casing or other tubing, and the local coolingof the casing by the cooled end when it is pointing in the direction ofthe circumferential location of the optical fiber outside the casing orother tubing is detected by the optical fiber as an increase or decreasein local temperature. By knowing the rotational position of the heatedend around the inner circumference of the casing or other tubing at thetemperature maxima, or by knowing the rotational position of the cooledend around the inner circumference of the casing or other tubing at atemperature minima, then the position of the optical fiber can beinferred as being at that position.

In a further variation of the second mechanism, the transducer may be aheated probe comprising a helical heater element positioned betweenfirst and second heater rings. The heated probe is wrapped around thedownhole device in a known relationship such that it is known which partof the probe corresponds to which part of the downhole device. Here thelocal heating of the casing or other tubing by the helical heaterelement and the first and second heater rings is detected by the opticalfiber as an increase in local temperature to produce at least onetemperature maxima. By knowing the relationship between the helicalheater element, first and second heater rings, and the downhole deviceat the at least one temperature maxima, the position of the opticalfiber can be inferred without any rotation of the downhole device beingrequired. In both the above mechanisms, therefore, a probe is providedthat contacts the inner surface of the casing or other production tubingand imparts energy to the surface at the contact point, whether as, forexample, heat energy, or mechanical (vibrational or acoustic) energy.Energy is imparted around the circumference of the casing or othertubing, and a fiber optic distributed sensor located on the outersurface of the casing or other tubing is used to measure and record theenergy that it receives whilst the probe is moved to impart energyaround the circumference. A record of energy versus position of theprobe around the circumference can be obtained, from which maxima in thedetected energy measurements can then be found. The position around thecircumference which gave the maximum measurement should be the positionat which the optical fiber of the fiber optic distributed sensor islocated.

In view of the above, from one aspect the present invention provides anapparatus, comprising a downhole device adapted to be inserted into awell-bore, the downhole device including a transducer arranged tocontact an interior surface of the well-bore to impart energy to thesurface at the contact point.

Another aspect of the invention provides a method of detecting theposition of a downhole optical fiber around a wellbore, comprising:deploying a downhole device into the well bore, the downhole deviceincluding a transducer arranged to contact an interior surface of thewell-bore to impart energy to the surface at the contact point;operating the downhole device within the well-bore; using an opticalfiber distributed sensor system to detect the energy imparted to thesurface at the contact point; and determining the position of theoptical fiber around the well-bore in dependence on the detected energy.

In an alternative mechanism, an optical fiber deployed along theexterior surface of the casing or tubing is arranged to impart energy tothe surface of the casing or tubing at the contact point, for example,the optical fiber may be heated so as to impart heat energy. A downholedevice deployed inside the casing or tubing and provided with at leastone sensor arranged to contact the interior surface of casing or tubingto detect the energy imparted by the optical fiber. In respect of heatenergy, the sensor detects the local heating of the casing or tubing inthe vicinity of the optical fiber, The at least one sensor on thedownhole device may be circumferentially rotated around the innersurface of the casing or other tubing so as to detect one or more maximain the detected energy as the at least one sensor moves over theinterior surface. By knowing the rotational position of the at least onesensor, the position of the optical fiber deployed along the exteriorsurface of the casing or tubing can be inferred as being at the one ormore positions generating the maxima.

In one variation of this mechanism, the at least one sensor is an arrayof sensors wrapped around the downhole device in a known relationship.The array of sensors are then able to detect one or more maxima in thedetected energy at the points of the array that are at or close to theat least one optical fiber. Thus, the position of the optical fiber maybe determined from the one or more maxima based on the knownrelationship between the array of sensors and the downhole device. Inthis respect, no circumferential rotation of the sensors are needed inorder determine the position of the optical fiber

In view of the above, a further aspect of the present invention providesan apparatus, comprising a downhole device adapted to be inserted into awell-bore, the downhole device including at least one sensor arranged tocontact an interior surface of the wellbore to detect energy from thesurface at the contact point. In some embodiments, the at least onesensor may be an array of sensors wrapped around the downhole device ina known relationship such that it is known which part of the array ofsensors corresponds to which part of the downhole device.

From a further aspect, the present invention provides a sensor system,comprising a downhole device including at least one sensor arranged tocontact an interior surface of the wellbore to detect energy from thesurface at the contact point, at least one optical fiber deployed alongthe exterior surface of the wellbore to impart energy to the interiorsurface of the wellbore, and a processor coupled to the at least onesensor to detect energy imparted to the interior surface of the wellboreby the at least one optical fiber. In particular, the optical fiber maybe heated so as to impart heat energy to the surface of the wellbore.

In further aspects, contact of a transducer with the interior surface ofthe well-bore is not required. This is particularly the case where theoptical fiber distributed sensor is operated as a distributedtemperature sensor, which is used to detect a change in heat energy ofthe well-bore casing, which may result from either local heating orcooling of the casing at discrete points. The heating or cooling may becaused in a contact manner, for example by a heated or cooled probe, or,at least in the case of heating, in a non-contact manner by an energyprojection device such as a laser beam, microwave emitter, or the like.The distributed temperature sensor is then able to detect maxima orminima in the temperature profile of the well-bore casing as the probeor beam is swept across the interior surface by the downhole device thatcarries it, and as a consequence the orientation of the downhole devicemay be determined.

From a further aspect, therefore, embodiments of the invention alsoprovide an apparatus, comprising: a downhole device adapted to beinserted into a well-bore, the downhole device including a transducerarranged to adapt the heat energy of an interior surface of thewell-bore at one or more discrete points so as to alter the temperatureof the surface of the well-bore at said one or more discrete points.

In one embodiment the transducer comprises a heated probe adapted tocontact the interior surface of the well-bore to impart heat energy tothe surface. In another embodiment the transducer may be an energyprojection device, such as, for example, a laser.

In one embodiment the transducer is a probe arranged to contact theinterior surface of the well-bore, and comprising a heated end adaptedto heat the interior surface of the well-bore and a cooled end adaptedto cool the interior surface of the well-bore.

In some embodiments the transducer is arranged to move such that the oneor more discrete points move over at least a portion of the interiorsurface of the well-bore. In other embodiments the transducer is furtherarranged to move such that the one or more discrete points move over atleast a portion of the interior surface at a longitudinal position alongthe wellbore. In further embodiments the transducer is further arrangedto move such that the one or more discrete points move over a wholecircumference of the interior surface of the wellbore at thelongitudinal position.

In some embodiments the heated probe comprises a helical heater elementpositioned between first and second heater rings, wherein the probe iswrapped around the downhole device in a known relationship such that itis known which part of the probe corresponds to which part of thedownhole device.

A further aspect of some embodiments of the invention provides anoptical fiber distributed temperature sensor system deployed down awell-bore and adapted to detect the temperature of a surface of thewell-bore by an apparatus as described above.

In some embodiments the system is further arranged to detect one or moremaxima or minima in the detected temperature as the transducer movesover the interior surface whereby to determine one or more positions ofa sensing fiber of the optical fiber distributed sensor system at theone or more positions that give the maxima or minima.

In one embodiment the transducer is a probe comprising a heated endadapted to heat the interior surface of the well-bore and a cooled endadapted to cool the interior surface of the well-bore, and the opticalfiber distributed sensor is an optical fiber distributed temperaturesensor system.

In one embodiment the system is further arranged to detect one or moreminima in the detected temperature as the one or more discrete pointsmove over the interior surface whereby to determine one or morepositions of a sensing fiber of the optical fiber distributed sensorsystem at the one or more positions that give the minima.

In one embodiment the transducer is a heated probe comprising a helicalheater element positioned between first and second heater rings, whereinthe probe is wrapped around the downhole device in a known relationshipsuch that it is known which part of the probe corresponds to which partof the downhole device, and the optical fiber distributed sensor is anoptical fiber distributed temperature sensor system.

In one embodiment the sensor system is further arranged to detect one ormore maxima in the detected energy at the points of the heated probethat are at or close to the sensing fiber of the optical fiberdistributed temperature sensor system whereby to determine positions ofthe sensing fiber based on the known relationship between the heatedprobe and the downhole device.

From a further aspect an embodiment of the invention also provides amethod of detecting the position of a downhole optical fiber around awellbore, comprising: deploying a downhole device into the well bore,the downhole device including a transducer arranged to adapt the heatenergy of an interior surface of the well-bore at one or more discretepoints so as to alter the temperature of the surface of the well-bore atsaid one or more discrete points; operating the downhole device withinthe well-bore; using an optical fiber distributed temperature sensorsystem to detect the temperature of the surface of the well-bore; anddetermining the position of the optical fiber around the well-bore independence on the detected temperature.

In one embodiment the operating step comprises imparting heat energy tothe interior surface around at least a majority of a circumference ofthe interior surface of the wellbore, and the determining step comprisesdetecting maxima in the detected temperature measurements andidentifying the one or more points at which said maxima occur, whereinthe position of the optical fiber can be inferred to be at or close tosaid points.

Further embodiments of the present invention improve upon thearrangement described in WO2013/030555 by using higher frequency,ultrasonic transducers that are significantly more directional thanconventional loudspeakers. Ultrasonic transducers, such as piezo orferroelectric transducers, are known in the art that generate highlydirectional soundwaves with frequencies from 100 KHz up to many (50)MHz. As directionality of a sound transducer is proportional to thefrequencies emitted therefrom, with higher frequencies typically beingmore directional, using an ultrasonic transducer results in asignificantly more directional output than with conventionalloudspeakers. Hence, if the fiber detects the highly directionalsoundwave, then it becomes possible to be more certain of theorientation of the object to which the transducer is affixed, knowingthe relative arrangement between the transducer and the object.

One problem with using such high frequency ultrasonic sources, however,is that a conventional distributed acoustic sensor system can typicallyonly detect sound up to about 100 kHz, and hence will be unable todetect such ultrasound sources. However, in some embodiments of thepresent invention this problem is solved by operating the DAS equipmentin a non-distributed mode, and in particular by operating the laser inthe DAS equipment in a continuous wave (cw) mode, such that cw lightpropagates along the fiber throughout sensing. The fiber is stillsensitive to incident ultrasonic vibrations, and the usual backscattereffects (e.g. Rayleigh, Brillouin and Raman) upon which DAS systems relystill occur, but because of the continuous wave operation the sensingequipment is unable to resolve the location of the incident sound alongthe sensing fiber (there are no pulses being sent along the fiber, thebackscatter from which can be timed to determine location). However, thesensing equipment in the DAS is still able to detect that suchbackscatter effects occur, and hence that there is incident ultrasonicenergy incident on the fiber somewhere. From this detection it can thenbe inferred, absent other sources of incident ultrasonic energy on thefiber, that the ultrasonic source on the perforating gun must bepointing at the fiber, and hence the relative rotational orientation ofthe fiber and the ultrasonic transducer (and hence the perforating gun)can also be inferred with more accuracy than in the case of the priorart.

The above described operation therefore implies a two stage operationfor use of the DAS system in aiding in location and orientation of theperforating gun. Firstly, the DAS system may be operated in normaldistributed mode, where sensing pulses are sent down the fiber in aconventional manner, to monitor the deployment of the perforating gundown the casing into the desired production zone. Then, once theposition of the perforating gun along the casing has been determined,the DAS system is put into a non-distributed mode of operation, where acontinuous signal is sent down the fiber, and backscatter therefromprocessed. As noted above, the use of a continuous signal prevents thesystem processor from resolving spatial location along the fiber, butprovided there are no other ultrasonic sources this is not an issue.However, the continuous wave fiber sensor is able to determine thatthere is an ultrasonic source incident on the fiber. The rotationalorientation of the perforating gun is then altered (essentially the gunis rotated within the casing), whilst the ultrasonic source operates, orthe rotational orientation is altered and then the source is operated atthe new orientation. When the fiber sensor detects the ultrasonic sourceit means that the source, which is highly directional, must be pointingat the fiber, and hence the rotational orientation of the perforatinggun, to which the source is affixed in known relation, can be accuratelydetermined. Having determined the rotational orientation of theperforating gun within the casing, the rotational orientation can thenbe controlled so that none of the shaped charges in the gun pointtowards the fiber, or other cabling on the outside of the casing.

In view of the above from a further aspect the present inventionprovides a method for determining the orientation of a downhole object,comprising: providing the downhole object with a high frequency highlydirectional sound source fixed in known relation to the object;operating the high frequency directional sound source; rotating thedownhole object; and detecting the high frequency directional soundsource using an optical fiber acoustic sensing system deployed downholewhen the high frequency directional sound source is pointing at theoptical fiber; wherein the rotational orientation of the downhole objectwith respect to the optical fiber is determined based on the detectionof the sound source and the known fixed relation between the soundsource and the object.

In one embodiment the high frequency directional sound source is anultrasonic transducer. The ultrasonic transducer may be arranged tooperate at frequencies in excess of 50 kHz, or in excess of 100 kHz, orin excess of 200 kHz.

Particularly, in some embodiments the optical fiber sensing system isarranged to operate in a continuous wave mode so as to be able to detectthe high frequency sound incident on the optical fiber. In someembodiments this lead to a two stage operation. First the optical fiberacoustic sensing system is operated as a convention distributed acousticsensor (DAS) system to locate the object downhole, and then operationswitches to a second mode, where the optical fiber acoustic sensingsystem operates in a continuous wave mode to determine the rotationalorientation of the object at the located position.

Further features and aspects of the invention will be apparent from theappended claims.

BRIEF DESCRIPTION OF DRAWINGS

Embodiments of the present invention, presented by way of example only,will now be described, with reference to the accompanying drawings,wherein like reference numerals refer to like parts, and wherein:

FIG. 1 is a drawing illustrating the prior art operation of aperforating gun;

FIG. 2 is a drawing from the prior art illustrating the wide-fieldeffects of loud speakers of the prior art;

FIG. 3 is a drawing of a perforating gun of an embodiment of the presentinvention, provided with at least one transducer thereon;

FIGS. 4a and 4b are drawings illustrating the operation and effects of afirst type of transducer in the form of a mechanical tapper, used as afirst embodiment of the present invention;

FIG. 5 is a diagram illustrating a typical deployment scenario forembodiments of the present invention;

FIGS. 6a and 6b are drawings illustrating the operation and effects of asecond type of transducer in the form of a heated probe used as a secondembodiment of the present invention;

FIG. 7 is a flow diagram illustrating the typical steps employed in anembodiment of the invention;

FIGS. 8a and 8b are drawings illustrating the operation and effect of athird type of transduced in the form of a probe with a varyingtemperature profile used as a third embodiment of the present invention;

FIGS. 9a and 9b are drawings illustrating the operation and effect of afourth type of transducer used as a forth embodiment of the presentinvention, wherein the transducer utilises a helical heater element;

FIGS. 10a and 10b are drawings illustrating the operation and effect ofan array of sensors on the perforated gun used as a fifth embodiment ofthe present invention;

FIG. 11 is a drawing of a perforating gun of an embodiment of thepresent invention, provided with at least one ultrasonic source thereon;

FIG. 12 is a drawing of a perforating gun of an embodiment of thepresent invention illustrating the narrow-field effects of the use of anultrasonic source;

FIG. 13 is a diagram illustrating a typical deployment scenario forembodiments of the present invention;

FIG. 14 is a graph illustrating the detection output of the continuouswave interferometer sensor system, with respect to rotational angle ofthe perforating gun; and

FIG. 15 is a flow diagram illustrating the typical steps employed in anembodiment of the invention.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

In an embodiment of the invention a perforating gun 32 is provided. Theperforating gun 32 comprises a generally cylindrical object havingsections provided therein in which shaped explosive charges 38 can bemounted. Suitable detonators (not shown) and control electronics (notshown) are also included, controlled via control line 34. In use, asknown in the art, the perforating gun is lowered into the casing of awellbore during the completion phase, and moved into the intendedproduction zone. The shaped charges are then fired to blow holes throughthe casing and cement into the surrounding rock strata.

In order to allow the rotational orientation of the perforating gun tobe determined when the gun is deployed within the wellbore casing, atransducer 36 is provided. The form of the transducer 36 differs betweenembodiments, as will be described. For example, in a first embodimentthe transducer comprises a mechanical tapper that taps against the innersurface of the casing or other tubing within which the perforating guntravels. In a second embodiment, however, the transducer is a heatedprobe that locally heats the internal surface of the casing or othertubing. The fiber optic distributed sensor is operated as a distributedtemperature sensor, as is known in the art, and detects the localheating of the casing in the vicinity of the optical fiber when theheated probe is rotationally pointing towards the position of the fiberon the outside of the casing or other tubing.

Within FIG. 3 a single transducer is shown. However, in otherembodiments multiple transducers may be included, for example arrangedaround the circumference of the perforating gun. For example, thetransducers 36 may be equiangularly arranged around the circumference.In addition or alternatively, plural (e.g. two or more) transducers maybe located at the same rotational position on the perforating gun.

FIG. 5 illustrates a typical deployment scenario for embodiments of thepresent invention. Here, a wellbore 52 has been drilled, and casing 54installed therein, cement surrounding the casing to secure the casingwithin the wellbore 52. The casing is provided running along its outersurface with one or more optical fibers 56 or other cabling, forsignalling, sensing or control purposes. The cabling 56 including theoptical fiber is secured to the casing 54 via clamps 57, locatedtypically every few meters along the casing. During completion of thewellbore perforating gun 32 is inserted into the casing 54, and movedalong the casing 32 to the intended production zone of the well. Anoptical interferometric sensing system 58, which in one embodiment is adistributed acoustic sensing (DAS) system, is provided, connected tooptical fiber 56. The sensing system 58 may operate in a distributedacoustic sensing mode as known in the art to monitor the insertion ofthe perforating gun 32 into and along the casing 54. The DAS system maybe a Silixa® iDAS™ system, the details of operation of which areavailable at the URL http://www.com/technology/idas/, and which is alsodescribed in our earlier patent application WO2010/0136809, any detailsof which that are necessary for understanding the present inventionbeing incorporated herein by reference. Alternatively, when required tobe a temperature sensor, as required by one of the embodiments to bedescribed below, then the optical interferometric sensing system 58 maybe a Silixa® Ultima™ distributed temperature sensor, available fromSilixa Limited, of Elstree, UK, and described athttp://www.silixa.com/technology/dts/.

A first embodiment of the present invention will be described withrespect to FIGS. 4a and 4 b.

FIG. 4a illustrates that the transducer 36 may be an electrical ormechanical tapper device 36 a, that is arranged to rotate about an axisand tap at discrete points on the inner surface of casing 54 as itrotates through 360 degrees. In this embodiment the opticalinterferometric sensing system 58 operates as a distributed acousticsensor (DAS), which listens to the acoustic energy from the taps anddetermines its amplitude and/or power. A plot of the measured amplitudeand/or power with respect to angular position of the tapper as itrotates within the casing is made, as shown in FIG. 4b . With referenceto the orientational axes shown in FIG. 4a , a minima in the measuredamplitude or power plot is expected when the tapper is aligned with thex-axis of FIG. 4a i.e. when it is substantially orthogonal to theposition of the optic fiber 56, whilst a primary maxima in amplitude orpower is obtained when the tapper 36 a is tapping directly at the fiber56. In addition, a secondary maxima in the measured signal is obtainedwhen the tapper 36 a is tapping directly away from the fiber, i.e. whenit is tapping in an opposite direction 180 degrees away from theposition of the fiber. That is, with respect to the axes shown on FIG.4a , minima in the detected signal occur when the tapper is pointing inthe + or −x directions, whilst a primary (largest) maxima is obtainedwhen the tapper is pointing directly towards the fiber 56, (i.e. in the+y direction) and a secondary (smaller) maxima is obtained when thetapper is pointing directly away from the fiber (i.e. in the −ydirection).

Regarding the clamp 57 that clamps the fiber 56 to the casing, in thisembodiment it is preferable (although not essential) that the clampcontains a flexible filler material to permit the fiber to have agreater freedom of movement in the +/−y directions, to permit the fiberto be more responsive to the vibrational energy of the tapper when thetapper is pointed directly toward the fiber.

A second embodiment of the invention will now be described with respectto FIGS. 6a and 6b . In this embodiment the optical interferometricsensing system 58 operates as a distributed temperature sensor (DTS)that acts to determine the temperature of the casing 54, inter alia. Thetransducer 36 is a heated probe, similar to the tip of a soldering iron,that is rotationally mounted on the perforating gun, or alternatively onanother down-hole device that acts as a carriage for the probe. In someembodiments this may be preferable, so that the heated tip is notmaintained near the explosives that are contained within the perforatinggun. The heated probe is in contact with the inner surface of the casing54, and acts to heat the casing wall in the immediate vicinity of theprobe. The degree of local heating provided by the probe need not belarge, and may even be less than 1K, for the reason that modern DTSsystems have very high temperature resolutions, as high as 0.01K.

The local heating of the casing wall in the immediate vicinity of theheated probe 36 b is detected by the optical fiber, which forms part ofthe DTS system, and the DTS system is able to plot measured temperatureagainst the rotational position of the heated probe 36 b, to give atypical plot as shown in FIG. 6b . From FIG. 6b it can be seen that asingle maxima is obtained in the temperature plot against rotationalangle of the probe at the point where the probe is pointing directlytowards the optical fiber i.e. the heated tip of the probe is closest tothe optical fiber. By detecting this maxima in the temperature plot theangular position of the optical fiber around the casing 54 can beinferred. That is, with reference to the axes shown in FIG. 4a , asingle maxima is obtained when the probe is pointed in the +y directioni.e. directly at the fiber.

With respect to the clamp 57 that clamps the fiber to the casing, aconventional clamp may be used; there are no special considerations forthe clamp in this embodiment.

FIG. 7 is a flow diagram illustrating the sequence of operations in thedescribed embodiments, given the equipment described above. Inparticular, at s.7.2 the interferometer sensor system is first operatedin conventional distributed acoustic sensing mode, whilst theperforating gun 32 is inserted into the casing. In this way the DAS canthe track the location of the perforating gun at step 7.4, as the gun ismoved along the casing into the desired production zone of the well thatis to be perforated.

Once the location of the gun within the well casing has been determined,and the gun located where required, then at step 7.6 the tapper or heatprobe are activated and the perforating gun (or other downhole carrierdevice on which they are mounted) is rotated through 360 degrees (orthrough any angle required to detect the fiber) whilst the optical fibersensing system (i.e. DAS or DTS, as appropriate) records its detectionoutput. Once the tapper or heat probe have been activated against theinner wall of the casing or other tubing through a sufficient arc todetect the fiber, the plot of measurements made by the DAS or DTS systemcan then be examined to determine any maxima therein, and thereby inferthe angular (or rotational) position of the fiber around the casing atthat point along the casing, as previously described. This determinationis performed at step 7.8, as shown.

A third embodiment of the invention will now be described with respectto FIGS. 8a and 8b . In this embodiment the optical interferometricsensing system 58 operates as a distributed temperature sensor (DTS)that acts to determine the temperature of the casing 54, inter alia. Thetransducer 36 is a probe with a heated tip 36 c and a cooled tip 36 d,wherein the probe is heated on one side and cooled on the opposite side,that is rotationally mounted on a perforating gun, or alternatively onanother down-hole device that acts as a carriage for the probe. In someembodiments this may be preferable, so that the heated part of the probeis not maintained near the explosives that are contained within theperforating gun. The probe is in contact with the inner surface of thecasing 54, and acts to heat or cool the casing wall in the immediatevicinity of the probe. The degree of local heating provided by the probeneed not be large, and may even be less than 1K, for the reason thatmodern DTS systems have very high temperature resolutions, as high as0.01K.

The local heating or cooling of the casing wall in the immediatevicinity of the probe is detected by the optical fiber 56, which formspart of the DTS system, and the DTS system is able to plot measuredtemperature against the rotational position of the probe, to give atypical plot as shown in FIG. 8b . From FIG. 8b it can be seen that asingle maxima is obtained in the temperature plot against rotationalangle of the probe at the point where the probe is pointing directlytowards the optical fiber i.e. the heated tip 36 c of the probe isclosest to the optical fiber. Additionally, a single minima is obtainedin the temperature plot against rotational angle of the probe at thepoint where the probe is pointing directly away from the optical fiber,i.e. the cooled tip 36 d of the probe is pointing directly towards theoptical fibre and the heated tip 36 c of the probe is pointing directlyaway from the optical fiber. That is, with reference to the axes shownin FIG. 8a , a single maxima is obtained when the heated tip 36 c of theprobe is pointed in the +y direction i.e. directly at the fiber, and asingle minima is obtained when the cooled tip 36 d of the probe ispointed in the +y direction, i.e. directly at the fiber, and the heatedtip 36 c of the probe is pointed in the −y direction, i.e. directly awayfrom the fiber. Consequently, no rotation is needed in order to tellwhether the probe is pointing in a general direction towards the fiber,where there will be local heating of the casing wall, or in a generaldirection away from the fiber, where there will be a local cooling ofthe casing wall. Furthermore, by detecting this maxima or minima in thetemperature plot the angular position of the optical fiber around thecasing 54 can be inferred. In this respect, fewer rotation positionsneed to be measured in order to locate the cable position accurately.

A fourth embodiment of the invention will now be described with respectto FIGS. 9a and 9b . In this embodiment the optical interferometricsensing system 58 operates as a distributed temperature sensor (DTS)that acts to determine the temperature of the casing 54, inter alia. Thetransducer in this embodiment is a heated probe comprising a helicalheater element 90 wrapped around a perforating gun 32 (or other downholecarrier device), and two heater rings 92 a-b positioned at either end ofthe helical heater element 90. The helical heater element 90 and heaterrings 92 a-b are installed on the gun 32 in a predeterminedconfiguration. That is to say, the probe is installed on the gun 32 in aknown orientation such that it is known which parts of the helicalheater element 90 and heater rings 92 a-b correspond to which parts ofthe gun 32, and furthermore it is known how the helical heater element90 is positioned with respect to the heater rings 92 a-b. The helicalheater element 90 and heater rings 92 a-b are in contact with the innersurface of the casing 54, and act to heat the wall of the casing 54 inthe immediate vicinity. The degree of local heating provided by theprobe need not be large, and may even be less than 1K, for the reasonthat modern DTS systems have very high temperature resolutions, as highas 0.01K.

The local heating of the casing wall in the immediate vicinity of theprobe is detected by the optical fiber 56, which forms part of the DTSsystem, and the DTS system is able to plot measured temperature againstthe position of the probe. In the temperature plot, temperature peakswill be produced at the points where the heater rings 92 a-b and helicalheater element 90 are in contact with the parts of the casing 54 towhich the optical fiber 56 is attached, that is, the points at which theprobe is positioned closest to the optical fiber 56. In more detail,there will be two peaks at fixed positions produced in the location ofthe heater rings 92 a-b, and at least one peak produced from the helicalheater element 90, depending on the number of helical windings.

Generally, however, there will be at least as many peaks indicating thepresence of a helical winding as there are complete helical windings.For example, the helical heater element 90 may comprise two and a halfcomplete helical windings wrapped around the perforating gun 32. In onesituation, the gun 32 may be orientated such that the optical fiber 56is located above the two full helical windings and the half of helicalwinding, in which case three peaks in the temperature plot will begenerated. In another situation, the gun 32 may be orientated such thatthe optical fiber 56 is located above the two full helical windingsonly, in which case only two peaks will be generated in the temperatureplot.

Based on the known relationship between the positions of the helicalelement 90 and the heater rings 92 a-b, the distance between the helicalelement peak(s) and the heater ring peaks can be used to determine whichportion of the helical element 90 is causing the temperature peak(s).Therefore, since the configuration of the helical heater element 90 onthe gun 32 is also known, it is known which part of the gun 32 isclosest to the optical fiber 56 and thus the orientation of the gun 32inside the casing 54 can be inferred from this information.

For example, in FIG. 9a it is shown that the optical fiber 56 is locatedto one side of the gun 32. The heater rings 92 a-b produce temperaturepeaks 94 a-b respectively, identifying the top and bottom of theperforated gun 32 within the casing 54, wherein the longitudinalposition of the heater ring peaks 94 a-b along the length of the gun 32will be the same regardless of where the fiber 56 is located, asillustrated by FIG. 9b . As such the heater ring peaks 94 a-b act asreference points for temperature peaks 96 a-b produced by the helicalheater element 90, as will be described below. Furthermore, byidentifying where along the length of the optical fiber 56 the heaterrings 92 a-b are located, the location of the gun 32 along the length ofthe casing may also be inferred.

As stated previously, the relationship between the positioning ofhelical heater element 90 with respect to the position of the heaterrings 92 a-b is known. Therefore, the relative distances between theheater ring peaks 94 a-b and the helical heater element peaks 96 a-b canbe measured and compared with the known relationship to determine whichparts of the helical heater element 90 have produced the temperaturepeaks 96 a-b. As the position of the optical fiber 56 with respect tothe gun 32 varies, for example, as shown in FIG. 9b , the position ofthe helical heater element peaks 96 c-d with respect to the heater ringpeaks 94 a-b varies in dependence on the location of the optical fiber56, the distance between the helical heater element peaks 96 c-d and theheater ring peaks 94 a-b being used to determine which part of thehelical heater element 90 is causing the local heating of the casingwall. As a result, no rotation of the probe or the gun 32 is required inorder to determine the location of the optical fiber 56 around the probeor the gun 32.

A fifth embodiment of the invention will now be described with respectto FIGS. 10a and 10b . In this embodiment the transducer is at least onetemperature probe installed on a perforating gun (or other downholecarrier device). For example, the transducer is an array of sensorsinstalled on the perforating gun (or other downhole carrier device) in apredetermined configuration. The one or more optical fibers 56 runningalong the side of the casing 54 are heated, and may optionally form partof a heat-pulse system. The local heating of the casing wall by theoptical fiber 56 is detected by the array of sensors arranged in theknown configuration over the perforation gun 32. The array of sensors isable to detect the temperature around the circumference of the casing 54wall and then feed the temperature data back to some external processingmeans located at the surface via the control line 34 of the perforatinggun 32. The external processing means is able to determine which of thesensors provides the highest temperature reading, wherein the sensorwith the highest value is located nearest the fiber, the position of thefiber being determined based on the known position of the sensor.Consequently, there is no need to rotate the perforating gun 32 todetermine the location of the optical fiber.

Alternatively, as shown in FIG. 10a , a single probe 36 e isrotationally mounted on the perforating gun 32 and acts as a singletemperature sensor coupled to the control line 34 of the perforating gun32. The local heating of the casing 54 wall by the optical fiber 56 isdetected by the probe 36 e, and the external processing means coupled tothe control line 34 is able to plot measured temperature against therotational angle of the probe 36 e, to give a typical plot as shown inFIG. 10b . From FIG. 10b it can be seen that a single maxima is obtainedin the temperature plot against rotational angle of the probe at thepoint where the probe is pointing directly towards the optical fiberi.e. the probe 36 e is closest to the heated optical fiber. That is,with reference to the axes shown in FIG. 10a , a single maxima isobtained when the probe is pointed in the +y direction i.e. directly atthe fiber. By detecting this maxima in the temperature plot the angularposition of the optical fiber around the casing 54 can be inferred.

A further embodiment will now be described with respect to FIGS. 11 to15.

In order to allow the rotational orientation of the perforating gun tobe determine when the gun is deployed within the wellbore casing, anultrasonic transducer 36, such as piezo or ferroelectric transducer, isprovided. The transducer operates at any ultrasonic frequency, althoughpreferably from 100 kHz to 50 MHz, with the directionality of theultrasonic signal being dependent on the frequency and the transducerdesign. The precise design of the ultrasonic transducer is beyond thescope of the present application, suffice to say that many highlydirectional ultrasonic transducer designs are known in the art suitablefor use in the present embodiment.

Ultrasonic transducers can be obtained, for example, from Olympus NDTCorporation, of Waltham, Mass., USA, or from components suppliers suchas Premier Farnell, or RS. For example, the PROWAVE 235AC130TRANSMITTER, ULTRASONIC, 235 KHZ, 13 MM, available from Premier FarnellUK Limited, of Leeds, UK, provides a −6 dB beamwidth of only 15 degreesat 235 kHz.

Within FIG. 11 a single ultrasonic transducer is shown. However, inother embodiments multiple ultrasonic transducers may be included, forexample arranged around the circumference of the perforating gun asshown in FIG. 12. Here the arrangement is such that the transducers 36are equiangularly arranged around the circumference. In addition oralternatively, plural (e.g. two or more) ultrasonic transducers may belocated at the same rotational position on the perforating gun (notshown in FIG. 12). Where plural transducers are provided arranged aroundthe circumference of the gun, then the transducers may operate on thesame frequency, provided the beamwidths are narrow enough so as not tosignificantly overlap. For example, provided the −6 dB beamwidths ofrotationally adjacent transducers do not overlap, then there should besufficient separation. In FIG. 12, the dotted lines illustrate examplesoundfields from the transducers. As shown, the sound beamwidths arevery narrow, thus providing greater accuracy in determining therotational orientation of the gun.

However, in other more preferable embodiments, the transducers 36arranged at different positions around the circumference of the gunoperate on different frequencies. Providing different known frequenciesfrom transducers at known relative positions can help the acousticsensing system resolve the rotational orientation of the perforating gunwithin the casing more accurately.

Where there are plural (two or more) transducers located side by side atthe same angular position on the circumference of the gun then thesetransducers should operate at different frequencies. In such a case thedifferent frequencies would be picked up by the fiber optic acousticsensor simultaneously, when the plural transducers are commonly directedat the fiber. The different frequencies can act as both anidentification and rotational position signature for the perforatinggun, and provide a measure of anti-jamming performance, for example inthe presence of an inadvertent interfering signal. For example, theside-by-side transducers may operate at two known ultrasonicfrequencies, which may be widely separated in the spectrum, for exampleby 50 kHz or more. In use the fiber optic acoustic sensor would pick upboth signals simultaneously, at the same rotational position of the gun.If the rotational position that provides the maximum value for bothsignals is found, then it is highly likely that the gun is in a positionwhere the transducers are pointing directly at the fiber, and theincident ultrasound on the fiber is as a result of a direct path fromthe transducers to the fiber, rather than having suffered anyreflections or multi-path propagation between the transducers and thefiber. In such a case, the ability of the arrangement to accuratelydetermine the rotational position of gun with respect to the fiber isincreased.

FIG. 13 illustrates a typical deployment scenario for embodiments of thepresent invention. Here, a wellbore 52 has been drilled, and casing 54installed therein, cement surrounding the casing to secure the casingwithin the wellbore 52. The casing is provided running along its outersurface with one or more optical fibers 56 or other cabling, forsignalling, sensing or control purposes. The cabling 56 including theoptical fiber is secured to the casing 54 via clamps 57, locatedtypically every few meters along the casing. During completion of thewellbore perforating gun 32 is inserted into the casing 54, and movedalong the casing 32 to the intended production zone of the well. Anoptical interferometric sensing system 58, such as a distributedacoustic sensing (DAS) system is provided, connected to optical fiber56, which may operate in a distributed acoustic sensing mode as known inthe art to monitor the insertion of the perforating gun 32 into andalong the casing 54. The DAS system may be a Silixa™ iDAS™ system, thedetails of operation of which are available at the URLhttp://www.silixa.com/technology/idas/, and which is also described inour earlier patent application WO2010/0136809, any details of which thatare necessary for understanding the present invention being incorporatedherein by reference.

In the present embodiment the sensing system 58 may operate in adistributed acoustic sensing mode to monitor the insertion of theperforating gun 32 into the casing 54, and to determine the position ofthe gun 32 along the casing. However, the sensing system 58 may then beswitched to operate in a continuous wave mode, which is used todetermine the rotational orientation of the gun within the casing. Inthe continuous wave mode, the laser of the sensing system is operated ina continuous wave mode to continually send laser light along the fiberduring the sensing periods. The fiber is affected by incident ultrasonicsound waves from the ultrasonic transducers in the same manner as knownin the art i.e. Rayleigh, Brillouin, and Raman backscatter occur,dependent on the incident sound energy, but due to the continuous wavepropagating in the fiber rather than pulses, any timing information,which is indicative of location along the fiber is lost. Therefore, thecontinuous wave backscatter from the incident ultrasonic wave can bedetected and resolved by the interferometer detector unit in theinterferometric sensing system 58 to detect the ultrasonic incidentsound energy on the fiber, but not to locate it along the fiber—it issimply possible to tell that such ultrasonic sound energy is incident onthe fiber somewhere along its length.

The advantage of the continuous wave operation, however, is that becausethere is no need to take into account pulse timing of pulses propagatingalong the fiber in the detector to determine location, the detector isable to detect much higher frequency sound incident on the fiber than isthe case than when operating in distributed (DAS) mode, and inparticular should be able to detect incident ultrasound across theultrasound frequency band. Hence, in the present embodiment, with thesensor system 58 operating in continuous mode, any ultrasound beingemitted by source 36 on the perforating gun will be detected by thesensor system 58 as the arc of emitted ultrasound sweeps over the fiberas the perforating gun is caused to rotate in the casing. FIG. 14illustrates an example output plot of the amplitude of sound atultrasound frequency ω (which may be in the range e.g. 100 kHz to 50MHz) with respect to rotational angle θ of the perforating gun 32 withinthe casing 54, as detected by sensor system 58 operating in continuouswave mode. As will be seen, as the gun 32 rotates within the casing theoutput amplitude A(ω) at frequency ω remains substantially constant at abackground level, until the source 36 is pointing at the fiber atrotational position θ₁. At that rotational position the ultrasonicsource 36 is pointing directly at the fiber, and this manifests itselfas a spike in the detected sound on the fiber at frequency ω of theultrasonic source. Hence, at that point the operator knows thatultrasonic source 36 is pointing directly at the fiber, and by thenknowing the position of the source 36 on the perforating gun 32, therotational orientation of the perforating gun is thus found.

FIG. 15 is a flow diagram illustrating the sequence of operations in thepresent embodiment, given the equipment described above. In particular,at s.15.2 the interferometer sensor system is first operated inconventional distributed acoustic sensing mode, whilst the perforatinggun 32 is inserted into the casing. In this way the DAS can the trackthe location of the perforating gun at step 15.4, as the gun is movedalong the casing into the desired production zone of the well that is tobe perforated.

Once the location of the gun within the well casing has been determined,and the gun located where required, the interferometer sensing system 58is then switched into continuous wave mode operation, at s.15.6. Asdescribed above, this prevents the sensor form determining position ofincident sound along the fibre, but allows the sensor to detect incidentsound of much higher frequency that is incident anywhere along thefiber. With the sensing system 58 operating in this mode, the one ormore ultrasonic transducers 36 provided on the perforating gun 34 areturned on, and caused to emit a highly directional ultrasound beam. Theperforating gun is then rotated in the casing, such that the ultrasoundbeam sweeps around as the gun rotates (s.15.8). When the gun is rotatedsuch that ultrasound source is pointing at the fiber 56 the ultrasoundbeam sweeps over the fiber, thus causing backscatter effects in thefiber, which are detected by the interferometric sensor system 58, thusmanifesting themselves as a peak in the sensor output, as described.When the peak is detected the operator then knows that at the point theperforating gun is oriented such that the ultrasound source is pointingat the fiber, and hence given a priori knowledge of the location andorientation of the source on the gun, the rotational orientation of thegun within the casing is found.

In one preferred embodiment, the acoustic source 36 is located so thatits beam is not located on the same radial axis as the axes of fire ofany of the shaped charges 38. In such an embodiment, when the acousticsource beam is pointing at the fiber, and the high frequency soundtherefrom is being detected as incident on the fiber, the operator thusknows that at that point none of the shaped charges are pointing at thefiber, and hence it is safe to fire the charges.

Various modifications may be made to the above described embodiments, toprovide further embodiments. For example, whilst in the secondembodiment above we mention that the heat probe may be carried on adifferent down-hole device than the perforating gun, such modificationalso applies to the first embodiment. That is, in further embodimentsinstead of being carried on the perforating gun the transducer, whetherit be a tapper or heat probe, is instead carried on another downholedevice, for example a dedicated downhole pig, or other wireline orslickline downhole tool whose purpose is to mount and transport thetransducer. In such a case embodiments of the invention are used tolocate the optical fiber external to the casing, and any perforating gunthat follows the pig or other downhole tool is then aimed independently,given the obtained knowledge of the location of the fiber from theembodiments of the invention.

As another variant embodiment, based on the second embodiment describedabove, instead of using a heated probe to impart heat energy to theinterior wall of the casing, instead a high power semiconductor diodelaser is used instead. That is, a high power laser diode is carried by adownhole tool, and once in situ may be activated to direct a high power(e.g. >˜1 W) substantially collimated beam at the interior wall, so asto heat the wall at the point of incidence. The laser diode may then berotated, or the downhole tool on which it is mounted rotated, so as toslowly sweep the laser beam around the interior circumference of thecasing at the longitudinal position along the casing to be measured. Anexample high power laser diode is, for example, the TO-220 laser diode,available from OSRAM Opto Semiconductors GmbH of Wernerwerkstrasse 2,D-93049 Regensburg, Federal Republic of Germany. Other similar laserdiodes are also available, that may be suitable for downholeapplications, and in particular be able to operate at relatively highambient temperatures encountered downhole.

As noted, the laser beam incident on the interior wall of the casingheats the wall at the point of incidence, and the increased energy canbe detected by the optical fiber distributed temperature sensor in thesame manner as described previously with respect to the secondembodiment. That is, as the laser sweeps around the interiorcircumference of the wall, the DTS measures the temperature of thecasing during the sweep to determine a temperature profile with respectto sweep angle, and the angular position at which a maxima is presentshould correspond to the position of the fiber around the casing, atthat longitudinal measurement position. In this respect, the obtainedtemperature profile with respect to laser sweep angle should be similarto that of FIG. 6b , with a single maxima at the angular position of thefiber on the exterior of the casing. This position is determined by theDTS, and output to the user, as described previously in respect of thesecond embodiment.

With this variant on the second embodiment, therefore, a non-contactarrangement is provided, where there is no contact required on theinterior wall of the casing. Instead, directional electromagneticenergy, in this instance in the form of a laser, is directed at theinterior wall of the casing, in order to heat it up.

In this respect therefore, the wavelength of the laser may be any thatprovides a suitably collimated beam so as to be able to heat a discretespot on the interior surface of the casing. For example, the wavelengthof the laser may extend from the infra-red downwards, provided suitablysmall devices are available that can be deployed downhole at reasonablecost.

Various further modifications to the above described embodiment may bemade, whether by way of addition, deletion, or substitution, to providefurther embodiments, any and all of which are intended to be encompassedby the appended claims.

1-71. (canceled)
 72. An apparatus, comprising: a downhole device adaptedto be inserted into a well-bore, the downhole device including atransducer arranged to adapt the heat energy of an interior surface ofthe well-bore at one or more discrete points so as to alter thetemperature of the surface of the well-bore at said one or more discretepoints.
 73. An apparatus according to claim 72, wherein the transducercomprises a heated probe adapted to contact the interior surface of thewell-bore to impart heat energy to the surface.
 74. An apparatusaccording to claim 72, wherein the transducer is a probe arranged tocontact the interior surface of the well-bore, and comprising a heatedend adapted to heat the interior surface of the well-bore and a cooledend adapted to cool the interior surface of the well-bore.
 75. Anapparatus according to claim 72, wherein the downhole device is atransporter pig, perforating gun, or other wireline or slicklinedownhole device on which the transducer may be carried.
 76. (canceled)77. An apparatus according to claim 72, wherein the transducer isarranged to move such that the one or more discrete points move over atleast a portion of the interior surface of the well-bore.
 78. Anapparatus according to claim 77, wherein the transducer is furtherarranged to move such that the one or more discrete points move over atleast a portion of the interior surface at a longitudinal position alongthe wellbore.
 79. An apparatus according to claim 78, wherein thetransducer is further arranged to move such that the one or morediscrete points move over a whole circumference of the interior surfaceof the wellbore at the longitudinal position.
 80. An apparatus accordingto claim 73, wherein the heated probe comprises a helical heater elementpositioned between first and second heater rings, wherein the probe iswrapped around the downhole device in a known relationship such that itis known which part of the probe corresponds to which part of thedownhole device.
 81. An optical fiber distributed temperature sensorsystem having a sensing optical fiber deployed down a well-bore, theoptical fiber distributed temperature sensor system being adapted todetect the change in temperature of a surface of the well-bore caused byan apparatus according to claim 72 contained within the well-bore.
 82. Asystem according to claim 81, wherein the system is further arranged todetect one or more maxima or minima in the detected temperature wherebyto determine one or more relative positions of the sensing optical fiberof the optical fiber distributed sensor system with respect to theorientation of the downhole device.
 83. A system according to claim 82,wherein the transducer is a probe comprising a heated end adapted toheat the interior surface of the well-bore, the heated end beingarranged to move over the interior surface of the well-bore.
 84. Asystem according to claim 83, wherein the system is further arranged todetect one or more maxima in the detected temperature as the one or morediscrete points move over the interior surface whereby to determine oneor more positions of a sensing fiber of the optical fiber distributedsensor system at the one or more positions that give the maxima.
 85. Asystem according to claim 81, wherein the transducer is a heated probecomprising a helical heater element positioned between first and secondheater rings, wherein the probe is wrapped around the downhole device ina known relationship such that it is known which part of the probecorresponds to which part of the downhole device, and the optical fiberdistributed sensor is an optical fiber distributed temperature sensorsystem.
 86. A system according to claim 85, wherein the sensor system isfurther arranged to detect one or more maxima in the detected energy atthe points of the heated probe that are at or close to the sensing fiberof the optical fiber distributed temperature sensor system whereby todetermine positions of the sensing fiber based on the known relationshipbetween the heated probe and the downhole device.
 87. A method ofdetecting the position of a downhole optical fiber around a wellbore,comprising: deploying a downhole device into the well bore, the downholedevice including a transducer arranged to adapt the heat energy of aninterior surface of the well-bore at one or more discrete points so asto alter the temperature of the surface of the well-bore at said one ormore discrete points; operating the downhole device within thewell-bore; using an optical fiber distributed temperature sensor systemto detect the temperature of the surface of the well-bore; anddetermining the position of the optical fiber around the well-bore independence on the detected temperature.
 88. A method according to claim87, wherein the operating step comprises imparting heat energy to theinterior surface around at least a majority of a circumference of theinterior surface of the wellbore, and the determining step comprisesdetecting maxima in the detected temperature measurements andidentifying the one or more points at which said maxima occur, whereinthe position of the optical fiber can be inferred to be at or close tosaid points.
 89. An apparatus according to claim 72, the transducercomprising an electromagnetic energy projection device arranged todirect electromagnetic energy at an interior surface of the well-bore toimpart energy to the surface at an incident point.
 90. An apparatusaccording to claim 89, wherein the electromagnetic energy projectiondevice is a laser.
 91. An apparatus according to claim 89, wherein theelectromagnetic energy is collimated and heats the interior surface ofthe well-bore at the incident point above the ambient temperature. 92.An apparatus according to claim 89, wherein the electromagnetic energyprojection device is arranged to sweep over at least a portion, andpreferably a whole circumference, of the interior surface of thewell-bore so as to heat the interior surface above the ambienttemperature around the swept arc.